Compounds and methods for inhibiting corrosion in hydrocarbon processing units

ABSTRACT

Treatment compositions for neutralizing acidic species and reducing hydrochloride and amine salts in a fluid hydrocarbon stream are disclosed. The treatment compositions may comprise at least one amine with a salt precipitation potential index of equal to or less than about 1.0. Methods for neutralizing acidic species and reducing deposits of hydrochloride and amine salts in a hydrocarbon refining process are also disclosed. The methods may comprise providing a fluid hydrocarbon stream and adding a treatment composition to the fluid hydrocarbon stream. The treatment compositions used may have a salt precipitation potential index of equal to or less than about 1.0 and comprise either water-soluble or oil-soluble amines.

FIELD OF THE INVENTION

The present invention relates to the refinery processing of crude oil.Specifically, it is directed towards the problem of corrosion ofrefinery equipment caused by corrosive elements found in the crude oil.

BACKGROUND OF THE INVENTION

Hydrocarbon feedstocks such as petroleum crudes, gas oil, etc., aresubjected to various processes in order to isolate and separatedifferent fractions of the feed stock. In refinery process, thefeedstock is distilled so as to provide light hydrocarbons, gasoline,naphtha, kerosene, gas oil, etc.

The lower, boiling fractions are recovered as an overhead fraction fromthe distillation tower. The intermediate components are recovered asside cuts from the distillation tower. The fractions are cooled,condensed, and sent to collecting equipment. No matter what type ofpetroleum feed stock is used as the charge, the distillation equipmentis subjected to the corrosive activity of acids such as H₂S, HCl,organic acids, and H₂CO₃.

Corrosion in the crude overhead distillation equipment is mainly due tocondensation of hydrogen chlorides formed by hydrolysis of the magnesiumchloride and calcium chloride in crude oil. Typical hydrolysis reactionsmay proceed as in Equations I or II:

MgCl₂+2H₂O

2HCl+Mg(OH)₂  (I)

CaCl₂+2H₂O

2HCl+Ca(OH)₂  (II)

Corrosive attack on the metals normally used in the low temperaturesections of a refinery (i.e., where water is present below its dewpoint) is an electrochemical reaction generally in the form of acidattack on active metals in accordance with Equations III, IV or V:

At the anode: Fe

Fe⁺⁺+2e⁻  (III)

At the cathode: 2H⁺+2e⁻

2H  (IV)

At the cathode: 2H

H₂  (V)

The aqueous phase may be water entrained in the hydrocarbons beingprocessed and/or water added to the process for such purposes as steamstripping. Acidity of the condensed water is due to dissolved acids inthe condensate, principally HCl, organic acids, H₂S, and H₂CO₃. HCl, themost troublesome corrosive material, is formed by hydrolysis of calciumand magnesium chlorides originally present in the brines.

One of the chief points of difficulty with respect to corrosion occursabove and in the temperature range of the initial condensation of water.The term “initial condensate” as it is used herein signifies a phaseformed when the temperature of the surrounding environments reaches thedew point of water. At this point a mixture of liquid water,hydrocarbon, and vapor may be present. Such initial condensate may occurwithin the distillation tower itself or in subsequent condensers. Thetop temperature of the distillation tower is normally maintained abovethe dew point of water. The initial aqueous condensate formed contains ahigh percentage of HCl. Due to the high concentration of acids dissolvedin the water, the pH of the first condensate is quite low. For thisreason, the water is highly corrosive.

In the past, highly basic ammonia has been added at various points inhydrocarbon refining processes in an attempt to control thecorrosiveness of condensed acidic materials. Ammonia, however, has notproven effective with respect to eliminating corrosion occurring at theinitial condensate. It is believed that ammonia has been ineffective forthis purpose because it does not condense completely enough toneutralize the acidic components of the first condensate.

Several amines, including morpholine and methoxypropylamine, have beenused to successfully control or inhibit corrosion that ordinarily occursat the point of initial condensation within or after the distillationtower. These amines or their blends are added in pure form or as anaqueous solution. The high alkalinity of these amines serves to raisethe pH of the initial condensate rendering it less corrosive. The aminesare added in amounts sufficient to raise the pH of the liquid at thepoint of initial condensation to above 4.0, and in some cases, tobetween 5.0 and 6.0.

These amines, however, form hydrochloride salts that deposit on theinner surfaces of hydrocarbon refining equipment. These deposits cancause both fouling and corrosion problems and are most problematic inunits that do not use a water wash.

Some amines and their blends currently used produce less salt depositson hydrocarbon refining equipment than the amines listed above. Theseamines are also aqueous amines and are introduced in the distillationtower or downstream of the distillation tower. These amines includepicoline (U.S. Pat. No. 5,211,840) and blends comprisingdimethylethanolamine and dimethylisopropanolamine, (U.S. Pat. No.4,490,275) ethylenediamine, monoethanolamine and hexylmethylenediamine(U.S. Pat. No. 7,381,319). Additional amines include trimethylamine andN-methylmorpholine and their blends.

BRIEF DESCRIPTION OF THE INVENTION

It was surprisingly discovered that some amines are more effective atneutralizing the acidic species in hydrocarbon streams than ammonia. Itwas also surprisingly discovered that other amines are more effectivethan the comparative amines, trimethylamine and N-methylmorpholine.These effective amines also are effective at reducing deposits of aminesalt species on the internal surfaces of hydrocarbon processingequipment.

Accordingly, a treatment composition is disclosed for neutralizingacidic species and reducing hydrochloride and amine salts in a fluidhydrocarbon stream. The treatment composition comprises at least oneamine with a salt precipitation potential index of equal to or less thanabout 1.0.

In another embodiment, the treatment composition may comprise at leastone amine selected from the group consisting of dimethylpropylamine,1,4-dimethylpiperazine, N-methyldibutylamine, N-methyldipropylamine,ethylhexylamine, N-methylpyrrolidine, di-ethylhydroxylamine,dimethylcyclohexylamine, pyrrolidine, di-ethylpropargylamine,dimethyl-N-propylamine, di-N-propylamine,N,N,N,N-tetramethylethylenediamine (“TMEDA”), and furfurylamine.

In another embodiment, the treatment composition may comprise an aminewith a pKa equal to or greater than about 5.0. In yet anotherembodiment, the treatment composition may comprise an amine with a saltprecipitation potential index (“Salt PPI”) of equal to or less thanabout 0.5. Alternatively, the amine may have a Salt PPI of equal to orless than about 0.1.

In another exemplary embodiment, a method for neutralizing acidicspecies and reducing hydrochloride and amine salts in a hydrocarbonrefining process is disclosed. The method comprises providing a fluidhydrocarbon stream and adding a treatment composition to the fluidhydrocarbon stream. The treatment composition comprises at least oneamine with a Salt PPI of equal to or less than about 1.0.

In another method, the treatment composition may comprise at least oneamine selected from the group consisting of dimethylpropylamine,1,4-dimethylpiperazine, N-methyldibutylamine, N-methyldipropylamine,ethylhexylamine, N-methylpyrrolidine, di-ethylhydroxylamine,dimethylcyclohexylamine, pyrrolidine, di-ethylpropargylamine,dimethyl-N-propylamine, di-N-propylamine,N,N,N,N-tetramethylethylenediamine, and furfurylamine.

In another method, the treatment composition may comprise an amine witha pKa equal to or greater than about 5.0. In yet another method, thetreatment composition may comprise an amine with a Salt PPI of equal toor less than about 0.5. Alternatively, the amine may have a Salt PPI ofequal to or less than about 0.1.

In one embodiment, a method for neutralizing acidic species and reducingdeposits of hydrochloride and amine salts in a hydrocarbon refiningprocess is disclosed, wherein the treatment composition may be added tothe fluid hydrocarbon stream in an amount ranging from about 1 ppm toabout 1000 ppm by volume of the fluid hydrocarbon stream. In anothermethod, the treatment composition may be added at 300 ppm to 900 ppm byvolume of the fluid hydrocarbon stream. Alternatively, the treatmentcomposition may be added at about 300 ppm to about 700 ppm.

It was also surprisingly discovered that the effectiveness of someamines may be increased by selecting the addition point in thehydrocarbon refining process. It was also surprisingly discovered thatthere was a correlation between the addition point and the amine'ssolubility in oil or water. The effectiveness of oil-soluble amines maybe increased by adding them to the fluid hydrocarbon stream as it leavesthe desalter. The effectiveness of water-soluble amines may be increasedby adding them to the fluid hydrocarbon stream as it leaves thedistillation tower.

Accordingly, another exemplary embodiment discloses a method where thetreatment composition comprises at least one water-soluble amine. Inanother embodiment, the treatment composition comprising a water-solubleamine is added to a fluid hydrocarbon stream after it leaves thedistillation tower of a hydrocarbon refining process.

Another exemplary embodiment discloses a method where the treatmentcomposition comprises at least one oil-soluble amine. In anotherembodiment, the treatment composition comprising an oil-soluble amine iscontacted with a fluid hydrocarbon stream after it leaves the desalterof a hydrocarbon refining process.

In yet another exemplary embodiment, a method for neutralizing acidicspecies and reducing deposits of hydrochloride and amine salts in ahydrocarbon refining process is disclosed. The method comprisesproviding a fluid hydrocarbon stream; providing a first treatmentcomposition with at least one oil-soluble amine; providing a secondtreatment composition with at least one water-soluble amine; and addingthe first and second treatment compositions to the fluid hydrocarbonstream. Both the first and second treatment compositions comprise atleast one amine with a Salt PPI of equal to or less than about 1.0.

Another exemplary embodiment discloses a method wherein at least onewater-soluble amine is a member selected from the group consisting ofdimethyl propylamine, 1,4-dimethylpiperazine, N-methylpyrrolidine,di-ethylhydroxylamine, pyrrolidine, dimethyl-N-propylamine,N,N,N,N-tetramethylethylenediamine, and furfurylamine. Yet anothermethod discloses a method wherein at least one oil-soluble amine is amember selected from the group consisting of N-methyldibutylamine,N-methyldipropylamine, ethylhexylamine, dimethylcyclohexylamine,diethylpropargylamine, and di-N-propylamine.

Other embodiments disclose methods wherein at least one water-soluble oroil-soluble amine may have a pKa of equal to or greater than about 5.0.Yet other embodiments disclose methods wherein at least onewater-soluble or oil-soluble amine may have a Salt PPI of equal to orless than about 0.5. Alternatively, the Salt PPI may be equal to or lessthan about 0.1.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a simplified section of a hydrocarbon refining process; and

FIG. 2 shows a graph of amines and their salt precipitation potentialindices.

DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS

FIG. 1 (FIG. 1) shows a simplified section of a hydrocarbon refiningprocess. Crude (1) is fed through a series of heat exchangers (3) beforeentering at least one desalter (5). Desalted crude (7) enters anotherseries of heat exchangers (9) where it is preheated to about 200 to 700°F. before entering a flash drum (11), or preflash tower. The lights (13)from the flash drum may be fed directly to the distillation tower (15).The bottoms (17) from the flash drum may be fed to a direct-firedfurnace (19) before they are fed to the distillation tower (15). Thedistillation tower is often called an atmospheric tower as it operatesslightly above atmospheric pressure, typically around 1 to 3 atmospheresgauge.

The overhead distillation tower temperature usually ranges from 200 to350° F. While in the tower, the crude is distilled into multiplefractions, also called “sidecuts.” The sidecuts comprise heavy gas oil(21), light gas oil (23), diesel (25), and kerosene (27). The bottoms(37) exit the distillation tower for processing elsewhere (not shown).Naphtha vapor (29) exits the top of the distillation tower and enters aseries of heat exchangers (31). The naphtha vapor then enters at leastone condenser (33). A portion of the condensed naphtha stream is fedback into the top of the tower as reflux (35).

Some refining processes may not utilize a flash drum and instead feedcrude directly to a direct-fired furnace Likewise some operations havebeen omitted from FIG. 1 for the sake of brevity. These and other minordifferences in crude refining processes do not affect the scope of theinvention.

It was surprisingly discovered that some amines are more effective atneutralizing the acidic species in hydrocarbon streams than ammonia. Itwas also surprisingly discovered that other amines are more effectivethan the comparative amines, trimethylamine and N-methylmorpholine.These effective amines are also effective at reducing deposits of aminesalt species on the internal surfaces of hydrocarbon processingequipment.

Without limiting this specification to any particular theory ofoperation, the overall efficiency of a given amine may be predicted uponassessment of several factors. One such factor is the amine-HCl saltprecipitation potential index (“Salt PPI”). The Salt PPI may also beknown by those in the art as the salt volatility index. These indicesare merely a comparison of the precipitation potential of the amine saltto the salt of a typical neutralizing compound used in hydrocarbonrefining, ammonia.

Salt PPI may be calculated from the equation:

$\frac{\left\lbrack \frac{p_{225{^\circ}\mspace{14mu} {F.}}\left( {{NH}_{4}{Cl}} \right)}{p_{225{^\circ}\mspace{14mu} {F.}}\left( {{Amine} \cdot {Cl}} \right)} \right\rbrack + \left\lbrack \frac{p_{300{^\circ}\mspace{14mu} {F.}}\left( {{NH}_{4}{Cl}} \right)}{p_{300{^\circ}\mspace{14mu} {F.}}\left( {{Amine} \cdot {Cl}} \right)} \right\rbrack}{2}$

where p is the vapor pressure at either 225 or 300° F. The average SaltPPI over the 225 to 300° F. range is selected because these aminesusually have the requisite volatility characteristics at typical crudeoverhead operating temperatures. Namely, such amines are thermallystable at temperatures typical to the refining process, yet volatileenough to condense with the initial condensate. As can be seen from theequation, the salt of the typical neutralizing compound, ammonia, isused as a benchmark. If one were to substitute the vapor pressure ofammonia for the vapor pressure of the amine in the equation, the SaltPPI would be 1.0. Effective amines are those that are as good, if notbetter than the typical additive, ammonia. Thus, effective amines wouldhave a Salt PPI of equal to or less than 1.0. Other neutralizerscommonly used in hydrocarbon refining are trimethylamine andN-methylmorpholine. The Salt PPI of these comparative amines is equalto, or greater than 0.1. Thus, the most effective amines would have aSalt PPI of equal to, or less than 0.1. FIG. 2 shows a graph of aminesand their salt precipitation potential indices.

Accordingly, a treatment composition is disclosed for neutralizingacidic species and reducing hydrochloride and amine salts in a fluidhydrocarbon stream. The treatment composition comprises at least oneamine with a salt precipitation potential index of equal to or less thanabout 1.0.

A fluid hydrocarbon stream encompasses both gaseous and liquidhydrocarbon streams. Examples of fluid hydrocarbons include, but are notlimited to, crude oil, natural gas, condensate, heavy oil, processedresidual oil, bitumen, coker oils, coker gas oils, fluid catalyticcracker feeds and slurries, gas oil, naphtha, diesel fuel, fuel oil, jetfuel, gasoline, kerosene, crude styrene distillation tower feed, crudeethylbenzene column feed, pyrolsis gasoline, chlorinated hydrocarbonsfeed, or vacuum residual.

In one exemplary embodiment, at least one amine may have the structure:

where R₁, R₂, and R₃ may the same or different and are H, or alkyls of 1to 20 carbon atoms. The alkyls may be straight alkyls, branched alkyls,cycloalkyl rings, hydroxyl-substituted alkyls, or alkoxy-substitutedalkyls.

In another embodiment, the treatment composition may comprise at leastone amine selected from the group consisting of dimethylpropylamine,1,4-dimethylpiperazine, N-methyldibutylamine, N-methyldipropylamine,ethylhexylamine, N-methylpyrrolidine, di-ethylhydroxylamine,dimethylcyclohexylamine, pyrrolidine, di-ethyl propargylamine,dimethyl-N-propylamine, di-N-propylamine,N,N,N,N-tetramethylethylenediamine (“TMEDA”), and furfurylamine.

Another factor indicative of the overall efficiency of a given amine isthe logarithm of the acid dissociation constant, pKa. Generally, amineswith higher pKa values are more efficient neutralizers. Accordingly, inanother embodiment, the treatment composition may comprise an amine witha pKa equal to or greater than about 5.0.

In yet another embodiment, the treatment composition may comprise anamine with a salt precipitation potential index of equal to or less thanabout 0.5. Alternatively, amines may have a salt precipitation potentialindex of equal to or less than about 0.1.

In another exemplary embodiment, a method for neutralizing acidicspecies and reducing deposits of hydrochloride and amine salts in ahydrocarbon refining process is disclosed. The method comprisesproviding a fluid hydrocarbon stream and contacting the fluidhydrocarbon stream with a treatment composition. The treatmentcomposition comprises at least one amine with a salt precipitationpotential index of equal to or less than about 1.0.

In another method, the amine may have the structure:

where R₁, R₂, and R₃ may the same or different and are H, or alkyls of 1to 20 carbon atoms. The alkyls may be straight alkyls, branched alkyls,cycloalkyl rings, hydroxyl-substituted alkyls, or alkoxy-substitutedalkyls.

In another method, the treatment composition may comprise at least oneamine selected from the group consisting of dimethylpropylamine,1,4-dimethyl piperazine, N-methyldibutylamine, N-methyldipropylamine,ethylhexylamine, N-methylpyrrolidine, di-ethylhydroxylamine,dimethylcyclohexylamine, pyrrolidine, di-ethylpropargylamine,dimethyl-N-propylamine, di-N-propylamine,N,N,N,N-tetramethylethylenediamine, and furfurylamine. In anothermethod, the treatment composition may comprise an amine with a pKa equalto or greater than about 5.0.

In yet another method, the treatment composition may comprise an aminewith a salt precipitation potential index of equal to or less than about0.5. Alternatively, the amine may have a salt precipitation potentialindex of equal to or less than about 0.1.

In one embodiment, a method for neutralizing acidic species and reducingdeposits of hydrochloride and amine salts in a hydrocarbon refiningprocess is disclosed, wherein the treatment composition may be added tothe fluid hydrocarbon stream in an amount ranging from about 1 ppm toabout 1000 ppm by volume of the fluid hydrocarbon stream. In anothermethod, the treatment composition may be added at 300 ppm to 900 ppm byvolume of the fluid hydrocarbon stream. Alternatively, the treatmentcomposition may be added at about 300 ppm to about 700 ppm.

It was also surprisingly discovered that the efficiency of some aminesmaybe increased through selection of the addition point. It was alsosurprisingly discovered that there was a correlation between additionpoint and the amine's solubility in oil or water. The efficiencies ofwater-soluble amines may be increased by adding them to the fluidhydrocarbon stream as it leaves the distillation tower. The efficienciesof oil-soluble amines may be increased by adding them to the fluidhydrocarbon stream as it leaves the desalter.

Accordingly, another exemplary embodiment discloses a method where thetreatment composition comprises at least one water soluble amine. Inanother embodiment, the treatment composition is added to a fluidhydrocarbon stream after it leaves the distillation tower of ahydrocarbon refining process (FIG. 1, B).

Another exemplary embodiment discloses a method where the treatmentcomposition comprises at least one oil soluble amine. In anotherembodiment, the treatment composition is added to a fluid hydrocarbonstream after it leaves the desalter of a hydrocarbon refining process(FIG. 1, A).

In yet another exemplary embodiment, a method for neutralizing acidicspecies and reducing deposits of hydrochloride and amine salts in ahydrocarbon refining process is disclosed. The method comprisesproviding a fluid hydrocarbon stream, providing a first treatmentcomposition with at least one oil-soluble amine, providing a secondtreatment composition with at least one water-soluble amine, and addingthe first and second treatment compositions to the fluid hydrocarbonstream. Both the first and second treatment compositions comprise atleast one amine with a Salt PPI of equal to or less than about 1.0.

Another exemplary embodiment discloses a method wherein at least onewater-soluble amine is a member selected from the group consisting ofdimethylpropylamine, 1,4-dimethylpiperazine, N-methylpyrrolidine,di-ethylhydroxylamine, pyrrolidine, dimethyl-N-propylamine,N,N,N,N-tetramethylethylenediamine, and furfurylamine. Yet anothermethod discloses a method wherein at least one oil-soluble amine is amember selected from the group consisting of N-methyldibutylamine,N-methyldipropylamine, ethylhexylamine, dimethylcyclohexylamine,di-ethylpropargylamine, and di-N-propylamine.

Other embodiments disclose methods wherein at least one water-soluble oroil-soluble amine may have a pKa of equal to or greater than about 5.0.Yet other embodiments disclose methods wherein at least onewater-soluble or oil-soluble amine may have a Salt PPI of equal to orless than about 0.5. Alternatively, the Salt PPI may be equal to or lessthan about 0.1.

EXAMPLE

Several amines were tested to determine their efficiencies inneutralizing acidic species and reducing deposits of hydrochloride andamine salts. The neutralization efficiency of these amines was testedusing two-phase titration. For each amine tested, a titrand (100 ml) wasplaced in a flask. The titrand was designed to simulate an initialcondensate and comprised 90 vol % naphtha and 10 vol % water. Thetitrand was heated to 100° C. and maintained at that temperature whileamine titrant was added to the flask. The resulting pH at differentamine titrant concentrations are summarized in Table 1.

As shown in Table 1, all of the amines have a pKa greater than 5.0. Alsoshown in Table 1, all of the effective amines have a lower Salt PPI thanthe ammonia benchmark of 1.0. Other effective amines have Salt PPI equalto, or lower than at least one of the comparative amines.

TABLE 1 Neutral. Efficiency pH at Solubility Salt 250 500 1000 AminesOil/Water pKa PPI ppm ppm ppm Effective Amines Salt PPI less thanammonia benchmark di-N-propyl amine Oil 10.91 0.24 2.2 3.0 7.6 N,N,N,N-Water 8.97 0.27 4.7 6.7 8.3 tetramethylethylenediamine FurfurylamineWater 8.89 0.38 2.6 6.5 8.5 Comparative Amines Trimethylamine Water 9.760.10 2.6 8.0 8.8 N-methylmorpholine Water 7.10 0.18 2.4 5.4 6.8Effective Amines Salt PPI less than at least one comparative amineDimethyl propyl amine Water 9.90 <0.1 1.4 8.5 9.6 1,4-dimethylpiperazineWater 8.20 <0.1 3.7 5.5 7.6 N-methyldibutylamine Oil 10.31 <0.1 1.9 2.05.0 N-methyldipropylamine Oil 10.09 <0.1 2.4 2.8 5.6 Ethyhexylamine Oil9.0 <0.1 2.2 2.7 5.3 N-methylpyrrolidine Water 10.32 <0.1 2.2 6.8 8.1Diethylhydroxylamine Water 5.61 <0.1 2.4 4.1 5.0 DimethylcyclohexylamineOil 10.00 0.10 1.8 1.9 5.2 Diethylpropargylamine Oil 7.70 0.12 2.2 3.65.9

This written description uses examples to disclose the invention,including the best mode, and also to enable any person skilled in theart to practice the invention, including making and using any devices orsystems and performing any incorporated methods. The patentable scope ofthe invention is defined by the claims, and may include other examplesthat occur to those skilled in the art. Such other examples are intendedto be within the scope of the claims if they have structural elementsthat do not differ from the literal language of the claims, or if theyinclude equivalent structural elements with insubstantial differencesfrom the literal languages of the claims.

What is claimed is:
 1. A treatment composition for neutralizing acidicspecies and reducing hydrochloride and amine salts in a fluidhydrocarbon stream, said treatment composition comprising at least oneamine with a salt precipitation potential index of equal to or less thanabout 1.0.
 2. The treatment composition of claim 1, wherein at least oneof said amines is selected from the group consisting ofdimethylpropylamine, 1,4-dimethyl piperazine, N-methyldibutylamine,N-methyldipropylamine, ethylhexylamine, N-methylpyrrolidine,di-ethylhydroxylamine, dimethylcyclohexylamine, pyrrolidine,di-ethylpropargylamine, dimethyl-N-propylamine, di-N-propylamine,N,N,N,N-tetramethylethylenediamine, and furfurylamine.
 3. The treatmentcomposition of claim 1, wherein said amine has a pKa equal to or greaterthan about 5.0.
 4. The treatment composition of claim 1, wherein saidamine has a salt precipitation potential index of equal to or less thanabout 0.5.
 5. The treatment composition of claim 4, wherein said aminehas a salt precipitation potential index of equal to or less than about0.1.
 6. A method for neutralizing acidic species and reducing depositsof hydrochloride and amine salts in a hydrocarbon refining processcomprising: (a) providing a fluid hydrocarbon stream; and (b) adding atreatment composition to said fluid hydrocarbon stream, said treatmentcomposition comprising at least one amine with a salt precipitationpotential index of equal to or less than about 1.0.
 7. The method ofclaim 6, wherein at least one of said amines is selected from the groupconsisting of dimethylpropylamine, 1,4-dimethylpiperazine,N-methyldibutylamine, N-methyldipropylamine, ethylhexylamine,N-methylpyrrolidine, di-ethylhydroxylamine, dimethylcyclohexylamine,pyrrolidine, di-ethylpropargylamine, dimethyl-N-propylamine,di-N-propylamine, N,N,N,N-tetramethylethylenediamine, and furfurylamine.9. The method of claim 6, wherein said amine has a pKa equal to orgreater than about 5.0.
 10. The method of claim 6, wherein said aminehas a salt precipitation potential index of equal to or less than about0.5.
 11. The method of claim 10, wherein said amine has a saltprecipitation potential index of equal to or less than about 0.1. 12.The method of claim 6, wherein said treatment composition is added tosaid fluid hydrocarbon stream in an amount ranging from about 1 to about1000 ppm by volume of said fluid hydrocarbon stream.
 13. The method ofclaim 12, wherein said treatment composition is added to said fluidhydrocarbon stream in an amount ranging from about 300 to about 900 ppmby volume of said fluid hydrocarbon stream.
 14. The method of claim 13,wherein said treatment composition is added to said fluid hydrocarbonstream in an amount ranging from about 400 to about 700 ppm by volume ofsaid fluid hydrocarbon stream.
 15. The method of claim 6, wherein saidtreatment composition comprises at least one water soluble amine. 16.The method of claim 15, wherein said water-soluble amine is selectedfrom the group consisting of dimethylpropylamine,1,4-dimethylpiperazine, N-methylpyrrolidine, di-ethylhydroxylamine,pyrrolidine, dimethyl-N-propylamine, N,N,N,N-tetramethylethylenediamine,and furfurylamine.
 17. The method of claim 15, wherein said treatmentcomposition is added to said fluid hydrocarbon stream after said fluidhydrocarbon stream leaves a distillation tower of said hydrocarbonrefining process.
 18. The method of claim 6, wherein said treatmentcomposition comprises at least one oil soluble amine.
 19. The method ofclaim 18, wherein said oil-soluble amine is selected from the groupconsisting of N-methyldibutylamine, N-methyldipropylamine,ethylhexylamine, dimethylcyclohexylamine, di-ethylpropargylamine, anddi-N-propylamine.
 20. The method of 18, wherein said treatmentcomposition is added to said fluid hydrocarbon stream after said fluidhydrocarbon stream leaves a desalter of said hydrocarbon refiningprocess.
 21. A method for neutralizing acidic species and reducingdeposits of hydrochloride and amine salts in a hydrocarbon refiningprocess comprising: (c) providing a fluid hydrocarbon stream; (d)providing first treatment composition comprising at least oneoil-soluble amine with a salt precipitation potential index of equal toor less than about 1.0; (e) adding said first treatment composition tosaid fluid hydrocarbon stream after said fluid hydrocarbon stream leavesa desalter of said hydrocarbon refining process; (f) providing a secondtreatment composition comprising at least one water-soluble amine with asalt precipitation potential index of equal to or less than about 1.0;and (g) adding said second treatment composition to said fluidhydrocarbon stream after said fluid hydrocarbon stream leaves adistillation tower of said hydrocarbon refining process.
 22. The methodof claim 21, wherein at least one water-soluble amine is a memberselected from the group consisting of dimethylpropylamine,1,4-dimethylpiperazine, N-methylpyrrolidine, di-ethylhydroxylamine,pyrrolidine, dimethyl-N-propylamine, N,N,N,N-tetramethylethylenediamine,and furfurylamine.
 22. The method of claim 21, wherein at least oneoil-soluble amine is a member selected from the group consisting ofN-methyldibutylamine, N-methyldipropylamine, ethylhexylamine,dimethylcyclohexylamine, di-ethylpropargylamine, and di-N-propylamine.23. The method of claim 21, wherein at least one water-soluble amine hasa pKa equal to or greater than about 5.0.
 24. The method of claim 21,wherein at least one oil-soluble amine has a pKa equal to or greaterthan about 5.0.
 25. The method of claim 21, wherein at least onewater-soluble amine has a salt precipitation potential index of equal toor less than about 0.5.
 26. The method of claim 21, wherein at least oneoil-soluble amine has a salt precipitation potential index of equal toor less than about 0.5.
 27. The method of claim 21, wherein at least onewater-soluble amine has a salt precipitation potential index of equal toor less than about 0.1.
 28. The method of claim 21, wherein at least oneoil-soluble amine has a salt precipitation potential index of equal toor less than about 0.1.